Snubbing Unit Brings Middle East Well With Underground Blowout Under Control

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This paper describes the mobilization of a snubbing unit and blowout preventer (BOP) stack in the Middle East that enabled a well with an underground blowout and surface broaching to be brought under control within a short time. The mobilization timeline is provided, along with details about how the snubbing unit and BOPs were integrated with existing equipment to enable re-entry into the blowout well. The procedures and equipment used to enable a stable rig-up and well entry are discussed. The paper also describes the situation within the well and the procedures used to bring it under control.

Introduction and Background

A well drilled and completed in 1991 was last worked over and recompleted as a single-zone producer in 2010. On 25 March 2018, the perforated zone was isolated riglessly with a through-­tubing bridge plug (TTBP) and dumped cement, and new perforations were added between 3,994 and 4,010 ft. After perforation, wellhead pressure (WHP) was only 90 psi, which was not sufficient to flow the well to the nearby gathering center, and the well was shut in.

On 29 March, the gathering center reported that WHP had increased to 800 psi and that a nearby cathodic protection well had begun producing oil and gas to atmosphere. Investigations were performed on all production wells in the vicinity, and identified the well that was the source of communication with the cathodic protection well. The tubing pressure was found to be 800 psi, and the casing pressure was recorded as 650 psi.

Slickline was mobilized, and on 29 March, a tubing check revealed an obstruction in the tubing at 3,738 ft and provided evidence of damaged tubing at 1,960 ft. Between 29 and 31 March, multiple attempts to kill the well were made with brine weights between 9.0 and 9.6 ppg, followed by oil-based mud (OBM) at 16.0 ppg. Although pressures were temporarily reduced to 0 psi, they quickly returned to 800 psi on the tubing and 650 psi on the tubing by the 7-in. casing annulus. A total of 1,200 bbl of OBM was pumped into the well.

On 3 April, wireline was rigged up, and the logs run indicated that the tubing was severely damaged at approximately 1,951 ft, with many holes and wall loss between 1,296 and 3,727 ft. The 7-in. casing was found to have severe damage between 1,585 and 1,620 ft. Pressure and temperature logs indicated gas flow between the tubing and casing at 1,951 ft.

A TTBP was run on coiled tubing on 4 April and set at 3,732 ft. Discussions began the same day with a snubbing contractor about mobilizing a suitable snubbing unit and BOP stack. Because of the proximity of the well to an international airport, a main highway, and a nearby public center, as well as the risk of further surface broaching, time was of the essence in finding a solution to the problem with a high chance of success (Fig. 1).

Fig. 1—The situation in the blowout well on 4 April. CSG=casing; EOT=end of tubing; TOC=top of cement.

Planning, Mobilization, Rig-Up, and Well Operation

Mobilization, rig-up, and testing were completed within 12 days of receiving instructions to proceed. The well was controlled and left in a safe condition within an additional 14 days. The original plan, which was to slip and shear the holed completion out of the well under pressure, had to be continuously reviewed and modified as more information became available during the snubbing operation. Ultimately, that plan was not implemented. The rapid deployment and use of the snubbing unit brought control to a deteriorating situation and provided the fastest option to gain control of this well. The majority of the complete paper is devoted to a detailed description of the planning, equipment mobilization and rig-up, and snubbing and well-kill operation.

A major area of concern during planning was the possibility of further broaching around the wellhead, leading to instability of the wellhead and of the unit when rigged up. Finite-­element analysis (FEA) of the substructure revealed that in the event of sudden wellhead movement, the forces may not be contained. To mitigate this possibility, the cellar of the well was filled with cement to immediately below the 13⅝‑in. casing valves, and 1.25×480×48-in. steel plating was sourced to spread the ground load under the subframe. I‑beams were sourced and modified to be placed under the spans of the subframe, reducing the bending stresses at the points of concern. When the FEA was re-run, the concerns were alleviated.

The snubbing contractor used in-house software to ensure that snubbing operations could be performed safely on the well with regard to buckling forces above the lower stripping ram and the forces to which the completion would be exposed in the wellbore. These results were used during the operation to set safe hydraulic limits on the jack, ensuring that the pipe would neither be buckled nor parted.


The operation as performed differed substantially from the planned operation, which resulted in a faster resolution of the well problem than was anticipated. The primary time reduction was achieved by performing the dynamic kill through the original (holed) completion, enabling the completion to be retrieved with no pressure in the well, rather than having to shear it out joint-by-joint under pressure. The failure of the tubing cut on wireline also shortened the intervention time. This meant that the packer and the internal TTBP were all retrieved at one time, rather than in multiple trips in the hole with drillpipe.

A snubbing subject matter expert (SME) who was added to the team on location managed the intervention operation, enabling one point of contact between the oil company, the well-control contractor, other services, and the snubbing-company management and crews. Having the SME on location allowed rapid decision-making when changes were required, helped ensure the safety of personnel and equipment, and enabled the snubbing crews and supervisors to focus on completing the work.

Although the method of using slip rams and shear rams was not used to remove the holed completion on this particular well, it should not be disregarded as a viable method of removing a holed completion from a pressurized wellbore. BOP manufacturers and the general drilling community are usually of the opinion that, after a shear ram has been used one time, it should be inspected, redressed, and tested before being used again. This holds true when the ram has a well-control function in the BOP stack. In this particular case, however, the sealing function of the ram was not required. Only the cutting ability and redundancy was designed into the stack with the inclusion of another blind shear ram lower in the stack. The stack design was such that the shear and slip ram could be changed with the well under pressure and pipe in the hole by running competent pipe past the two lower pipe rams, and using them as an annular barrier while using the plugs and nipples in the work string as the internal barriers. The lower blind shear is available should the annular barriers fail during this process, and a full opening safety valve is available should the internal barriers fail.

The completion of 9.3 lb/ft 3.5-in. L80 tubing, when sheared with the BOP in use, was at the lower end of the capability of the ram with 750 psi on the well. The actual value observed at shearing was 950 psi, which was much less than the calculated value of 1,252 psi. The deformation of the lower fish section was never observed because it was milled off. The choice of mill for dressing the top of a sheared fish is crucial to the efficiency of the operation. The concave mill used in the first attempt was suboptimal, and the failure of the mill extended the length of the operation. In past operations, when dressing and fishing sheared pipe, a dressing shoe was added to the bottom of the overshot, enabling the dressing and latching of the fish to occur in one run. Previous experience shows that this operation can be achieved in less than 30 minutes. Unfortunately, these fishing tools were not available in country at the time of the intervention. When the shear-ram blocks were inspected after the job, there was no evidence of any deformation.

The availability of a snubbing unit working in country substantially reduced the amount of equipment that needed to be mobilized. This reduced the amount of space required on cargo planes and meant that all additional required equipment could be mobilized on two flights.

The close contact of the oil company with the customs department was invaluable in securing the rapid customs release of the unit directly upon landing at the airport; this rapid release reduced the mobilization time substantially over a normal customs-clearance process. The snubbing contractor’s internal processes of critical well review, logistics capability, a large fleet of snubbing units, personnel competence, and planning capability were key components in mobilizing a snubbing unit quickly and performing the intervention safely.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194283, “Rapid Deployment and Use of Snubbing Unit Brings Well With Underground Blowout and Surface Broaching Under Control,” by Albert Donaldson, SPE, Victor Marrero-Reyes, and William Scott, Halliburton, and Haitham Al-Mayyan, SPE, Kuwait Oil Company, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March.

Snubbing Unit Brings Middle East Well With Underground Blowout Under Control

01 January 2020

Volume: 72 | Issue: 1

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